Stringent U.S. environmental regulations require that the level of sulfur in gasoline be reduced by 90% from the current 300 ppm to 30 ppm and those in diesel be reduced by 97% from the current 500 ppm to 15 ppm or even lower. Hydrotreating is the most common method of removing organic sulfur and nitrogen compounds from petroleum fractions. In hydrotreating, oil and hydrogen are fed to a fixed bed reactor that is packed with a hydrodesulfurization (HDS) catalyst. The HDS operating temperature and pressure typically range from 300-400° C. and from 35 to 170 atm, respectively. The more difficult the sulfur removal needed, e.g., the higher the level of sulfur reduction, the more stringent the HDS operating temperatures and pressures become. In this regard, severe hydrotreating of gasoline feedstock to achieve low sulfur levels will saturate a significant portion of the olefins in the gasoline thereby substantially lowering the octane number. To minimize the octane loss, state of the art hydrotreating catalysts can isomerize the paraffins that are generated by olefin saturation. In a similar vein, it is expected that more robust catalysts must be developed and efficient process modifications implemented in order to remove the most refractory sulfur compounds. Most refiners have revamped their existing hydrotreating facilities and/or introduced new hydrotreating techniques in anticipation of these challenges as they comply with the new U.S. guidelines.
In recent years, industry has sought to develop less expensive desulfurization alternatives to hydrotreating. It is known that contacting a petroleum distillate to an oxidant converts sulfur and nitrogen compounds in the distillate into sulfones (or sulfoxides) and organic nitrogen oxides, respectively. These polar organic oxides can be removed from the distillate by solvent extraction and/or adsorption.
The oxidants currently used in oxidative desulfurization include, for example, peroxy organic acids, catalyzed hydroperoxides and inorganic peroxy acids. Almost all peroxy organic acids are derived by oxidation of organic acids with hydrogen peroxide. For example, EP 1004576 A1 to Druitte discloses a process for producing peracetic acid (PAA) by reacting hydrogen peroxide and acetic acid (AA) in an aqueous reaction medium.
U.S. Pat. No. 6,160,193 to Gore discloses a method for removing sulfur and nitrogen compounds from petroleum distillates, such as light gas oil (diesel) by oxidation with a selective oxidant. The oxidants are divided into three categories: (1) hydrogen peroxide based oxidants, (2) ozone based oxidants, and (3) air or oxygen based oxidants. The preferred oxidant is PAA that is formed by oxidizing glacial AA with 30-50% aqueous hydrogen peroxide. Since the peroxide is in the aqueous phase, a phase transfer agent is required to carry the peroxide from the aqueous phase to the oil phase where it oxidizes the sulfur and nitrogen compounds. The phase transfer, which is the rate-limiting step, significantly slows down the reaction rates. In this case, AA is the phase transfer agent for the oxidation of the sulfur and nitrogen compounds in the light gas oil. A small but not insignificant amount of AA remains in the oil phase in the reactor effluent.
Another disadvantage of using the aqueous oxidant disclosed in U.S. Pat. No. 6,160,193 is that the presence of water in the reactor effluent prevents phase separation of oil from the aqueous acid when the oil feed is vacuum gas oil, atmospheric residual oil, crude oil, or other heavy hydrocarbons. Complicating matters is the fact that the sulfones generated in the oxidation reactor also function as surfactants that inhibit phase separation. The spent AA, which is equivalent to 7 to 10 wt % of the oil feed, cannot be effectively removed from the oil, treated, and recycled without phase separation. In this regard, it has been demonstrated that an aqueous oxidant when mixed with virgin crude oil forms a very stable emulsified liquid mixture which does not readily separate into its two different phases. The aqueous oxidant tested consisted of hydrogen peroxide, water, as well as an organic acid which serves as the phase transfer agent. The presence of water can also cause a significant portion of the sulfones and organic oxides to precipitate from the reactor effluent. Indeed, solids may form at critical stages in the process thereby causing the valves, pumps, and even the adsorbent bed to malfunction. U.S. Pat. No. 6,160,193 does not appear to recognize the importance of the solid precipitation problem, which certainly occurs when the distillate contains more than 500 ppm sulfur and nitrogen compounds.
The specific solvents used to extract sulfones from the distillate phase in the process disclosed in U.S. Pat. No. 6,160,193 also tend to extract appreciable amounts of oil along with the sulfones and organic nitrogen oxides. In this regard, the prior art has disclosed many solvents for the sulfones extraction, including dimethyl sulfoxide (DMSO), formic acid, nitromethane, dimethyl formamide (DMF), trimethyl phosphate, and methanol. See, for example, U.S. Pat. No. 6,160,193 to Gore, U.S. Pat. No. 6,274,785 to Gore, U.S. Pat. No. 6,402,940 to Rappas, U.S. Pat. No. 6,406,616 to Rappas et al., and EP 0565324 A1 to Aida. However, none of these solvents has proven to be cost effective in removing sulfones from the oil.
U.S. Pat. No. 6,596,914 to Gore discloses the use of an aqueous acetic acid (AA) solvent which contains 1 to 5 wt % water to extract of sulfur oxides. In practice, it is difficult to remove (or recover) the AA because AA and water form an azeotrope consisting of 3 wt % AA and 97 wt % water. As a result, it is necessary to incorporate azeotropic distillation, liquid-liquid extraction or other operations into the process to recover the AA from an aqueous waste stream. In addition, separation equipment that is exposed to aqueous AA solvents must be made of special alloys given the corrosive nature of the solvents especially at elevated temperatures.
U.S. Pat. No. 6,402,940 to Rappas describes a process for desulfurizing fuels such as diesel oil to achieve a sulfur level of 2 to 15 ppm. The oxidant is hydrogen peroxide in a formic acid solution with no more than 25 wt % water. Since hydrogen peroxide is in the aqueous phase, the formic acid functions as the phase transfer agent that transfers the hydrogen peroxide to the oil phase. Given that formic acid is a more efficient phase transfer agent than acetic acid, the oxidation reaction rate is faster under formic acid. Nevertheless, phase transfer remains the rate-limiting step. A major drawback of the process relates to the spent acid recovery system. As described in the patent, the spent acid, which contains formic acid, water, sulfones, and trace amounts of diesel, is first fed to a flash distillation vessel to strip out the formic acid and water. The formic acid and water are then fed to an azeotropic distillation column. In this process, water is derived from oxidation reactions and from the aqueous hydrogen peroxide feed. Water must be removed from the spent formic acid stream in order to maintain the water balance in the process. It is known that formic acid and water form an azeotrope containing 77.5 wt % formic acid and 22.5 wt % water. However, according to the disclosed process, feed to the azeotropic distillation column contains more than 77.5 wt % formic acid. Consequently, the column could produce essentially pure formic acid in the overhead stream and about 77.5 wt % formic acid (but not pure water) in the bottom stream. In light of this, it would be impossible to remove water from the spent formic acid and it appears that the disclosed process is inoperable.
The presence of water in the reactor effluent also causes a significant portion of the sulfones and organic oxides to precipitate from the liquid phases and disrupt the process. As mentioned previously, water in the system also renders the process unsuitable for desulfurizing heavy hydrocarbons, such as vacuum gas oil, atmospheric resid, and crude oil, due to the difficulties in phase separation between oil and the aqueous acid.
A non-aqueous, oxidative desulfurization method for petroleum fuels was described in U.S. patent application 2004/0178122 to Karas et al. whereby fuel streams are exposed to an organic hydroperoxide oxidant, such as t-butylhydroperoxide (TBHP), in the presence of a titanium-containing silicon oxide catalyst. Due to the limited reactivity of the oxidant, the oxidative desulfurization reaction must to be catalyzed when operating at a reasonable temperature (80° C. according to Example 3). To slowdown the irreversible decay of the catalyst, the oil feed has to be pretreated to reduce the nitrogen content in the feed by adsorption or liquid-liquid extraction to very low levels (7 ppm according to Example 3). As is apparent, the process is restricted to handling light oil feeds with low nitrogen and sulfur contents. The necessity of employing pretreatment and catalysts also adds to the complexity and costs of the process.
Each of U.S. Pat. No. 6,596,914 to Gore, U.S. Pat. No. 6,406,616 to Rappas, U.S. Pat. No. 6,402,940 to Rappas, U.S. Pat. No. 6,274,785 to Gore, U.S. Pat. No. 6,160,193 to Gore, and U.S. patent application 2004/0178122 to Karas et al. teach to the use of solid adsorption to remove final traces of sulfones to produce ultra-low sulfur fuels. For example, U.S. Pat. No. 6,402,940 describes the use of non-activated alumina which has a relatively high surface area to remove sulfones. The non-activated alumina, however, must be regenerated following use. Similarly, U.S. Pat. No. 6,160,193 parenthetically discloses the use of silica gel and clay filter for removing sulfones.
The removal of sulfones by adsorption is typically a batch process, with respect to the adsorbents used, that encompasses an operation cycle and a separate regeneration cycle. The two cycles have flow sequences which are quite different from each other. In particular, the regeneration procedure entails numerous line and valve switches to direct different fluids in and out of the adsorption column and to reverse the flow directions at various stages in the regeneration cycle. Adding to the complexity is the fact that solid adsorbents normally have very limited sulfones loading and must be frequently regenerated. Furthermore, the adsorbent life, which is a critical factor to the success of this process, is uncertain and requires extensive evaluation. Although adsorption method is very selective in removing sulfones to produce ultra-low sulfur oil, its high capital investment and operating costs, limited capacity, and uncertainty in the adsorbent life, makes this method undesirable for commercial operations. The present invention has effectively eliminated the need of adsorption for final product polishing.
It is known that oxidative desulfurization can easily oxidize and remove thiophenic sulfur compounds, which cannot be readily treated by HDS due to the stereo hindrance effect around the sulfur atom in the molecules. In this regard, the order of the activities of representative thiophenic compounds in response to HDS treatment is as follows: DBT (dibenzothiophene)>4 MDBT (4-methyl dibenzothiophene)>4,6 DMDBT (4,6-dimethyl dibenzothiophene). See, Ind Eng Chem Res, 33, pp 2975-88 (1994). In contrast, it has been reported that the order of activity of thiophenic compounds in response to oxidative treatment is just the opposite, namely: 4,6 DMDBT>4 MDBT>DBT. See, Energy Fuels, 14, pp 1232-39 (2000). These observations suggest that oxidative desulfurization may be effective in removing even the most difficult residual sulfurs from hydrotreated oils to yield ultra-low sulfur products.
The concept of hydrotreating a hydrocarbon feed containing sulfur compounds prior to oxidation to facilitate the removal of hard-to-hydrotreat thiophenic compounds was described by Collins in Journal of Molecular Catalysis A: Chemical 117(1997), 397-403. More recently, U.S. Pat. No. 6,171,478 to Cabrera et al. (assigned to UOP LLC) disclosed a desulfurization process for hydrocarbon oil that includes HDS treatment followed by oxidation with an oxidizing agent. U.S. Pat. No. 6,277,271 to Kocal (assigned to UOP LLC) describes a similar process which includes the step of recycling the oxidized sulfur compounds to an upstream HDS reactor in order to allegedly increase hydrocarbon recovery. In particular, without the benefit of any experimental data, the patent asserts that sulfur oxides are easily convertible to H2S gas in the HDS unit. However, this assumption is dubious as explained herein.
U.S. patent application 2003/0094400 to Levy et al. describes a process for removing sulfur from hydrocarbons streams whereby organic sulfur is first oxidized into oxidized sulfur in the hydrocarbon stream which is then exposed to hydrogen to reduce the sulfur to H2S to yield a hydrocarbon stream which is substantially free of sulfur. The process uses an oxidation unit that is positioned in front of an HDS unit. Levy et al. states that any suitable oxidative method can be employed to oxidize the sulfur compounds including the use of aqueous oxidants that contain hydrogen peroxide and organic acids, e.g., formic acid. Levy et al. apparently failed to recognize that their own experimental evidence did not substantiate their position that it was easier to reduce the oxidized sulfur compounds to H2S and the corresponding hydrocarbons than it was to reduce the unoxidized sulfur compounds. Example 2 of Levy et al. provides data relating light atmospheric gas oil (diesel) that was used as a reactant feed. The diesel, which contained 435 ppm sulfur, was oxidized using a hydrogen peroxide aqueous solution in the presence of a formic acid catalyst (a phase transfer agent). The resulting oxidized diesel contained 320 ppm sulfur. Both the original diesel and the oxidized diesel were hydrotreated under identical conditions. The comparative conversion results from Levy et al. are summarized as follows:
Sulfur content in unoxidized diesel feed:435 ppmSulfur content in oxidized diesel feed:320 ppmSulfur inproduct (ppm)% Sulfur RemovedTemp (° C.)OxidizedUnoxidizedOxidizedUnoxidized25010319867.854.5300556082.886.2
The data show no significant difference in HDS results between the unoxidized and oxidized diesel feeds, especially at the HDS temperature of 300° C., which is more comparable to commercial HDS conditions for diesel feed. Therefore, Levy et al. appears to contradict the touted benefits that oxidizing the HDS feed would improve sulfur removal in the HDS unit or that recycling the oxidized sulfur compounds to the HDS unit would improve the oil recovery of down-stream oxidation process as is asserted in U.S. Pat. No. 6,277,271.
The lack of significant sulfur removal enhancement may be due to the fact that under certain HDS conditions some of the oxidized sulfur compounds are actually reduced to the original sulfur compounds instead of being reduced to the corresponding hydrocarbon compounds with a concomitant release of H2S in the HDS unit. Indeed this conclusion can be extrapolated from the experimental data disclosed in Example 1 of Levy et al. which describes oxidation of sulfur compounds followed by hydrotreatment under different reactor conditions. In particular, solutions of dibenzothiophene (DBT) sulfone (a model compound for the oxidized sulfur compounds) that contained 250 ppm sulfur in phenyl hexane solvent were used as the “feed.” The data in Example 1 purportedly showed that the oxidized sulfur compounds were all converted under the reactor conditions tested.
Subsequently, applicants of the present invention discovered that, depending upon the HDS conditions, DBT sulfone could be either totally hydrotreated to produce biphenyl (a model compound corresponding to totally desulfurized DBT sulfone) or partially hydrotreated to produce a mixture containing DBT (a sulfur compound corresponding to DBT sulfone before oxidation) and biphenyl. Therefore, in order to improve the recovery of oxidative desulfurization process through recycling an oil stream containing the oxidized sulfur compounds (mainly sulfones) to an upstream HDS unit, the operating conditions of the HDS unit must be properly adjusted to assure that the sulfones are converted to the corresponding hydrocarbon compounds and H2S and not to the original sulfur compounds that were present prior to oxidation. These original sulfur compounds can be regarded as “hard-to-hydrotreat” sulfur-type compounds, which have gone through the same HDS unit without being converted; they will most likely just continue to accumulate within the loop between the HDS and the oxidation step. The presence of these “hard-to-hydrotreat” sulfur compounds renders inoperable the concept of recycling oxidized sulfur compounds to an upstream HDS reactor in order to enhance hydrocarbon recovery as alleged in U.S. Pat. No. 6,277,271.
The recycling scheme disclosed in U.S. Pat. No. 6,277,271 uses hydrogen peroxide in aqueous acetic acid (or other aqueous carboxylic acids) as a preferred oxidant. This oxidant however is unsuitable for use with heavy hydrocarbon oil, such vacuum gas oil (VGO). The reason is that the sulfones in the oxidized VGO will emulsify the heavy oil phase with the aqueous phase thereby rendering phase separation extremely difficult when endeavoring to recover the oxidized VGO from the spent acid. Ironically, the only illustrative embodiment in the patent used VGO as the feed. Furthermore, the same illustrative embodiment teaches using severe HDS conditions for VGO with pressures of 1700 psig, temperatures up to 740° F. and hydrogen circulation of 5000 SCFB. At such extreme conditions, it is unrealistic to expect sulfur reduction in VGO of from 2 wt % (20,000 ppm) to 500 ppm. In fact, hydrotreated VGO with 500 ppm sulfur needs no oxidative desulfurization to further reduce sulfur before being fed to a fluid catalytic cracking (FCC) unit because with such a low sulfur (and low nitrogen) feedstock, the FCC unit can generate sufficiently clean gas products and FCC naphtha that require no post desulfurization treatment. In addition, it is unrealistic to assert that sulfur in the hydrotreated VGO can be reduced from 500 ppm to 50 ppm by the oxidation scheme described in the illustrative embodiment of the patent. Indeed, investigations have revealed that certain sulfur species (>50 ppm) in the hydrotreated VGO cannot be removed by the oxidation scheme.
A still further problem associated with the illustrative embodiment of U. S. Pat. No. 6,277,271 is the use of acetonitrile as the sulfur oxide extraction solvent. In fact, all the extractive solvents disclosed including acetonitrile, dimethyl formamide (DMF) and sulfolane are not suitable for sulfur oxide removal. The performance of acetonitrile and DMF for sulfur oxides extraction from an oxidized FCC diesel was reported in “Desulfurization of FCC Diesel Using H2O2-Organic Acids”, J. of University of Petroleum, China, 25(3), p. 26, Jun. 2001. Specifically, FCC diesel containing 0.8 wt % sulfur was oxidized with 30% aqueous H2O2 in the presence of formic acid. The oxidized sulfur compounds were extracted from the diesel by liquid-liquid extraction using several polar solvents including acetonitrile and DMF under the following conditions: 5% water in the solvents, 1:2 solvent-to-diesel ratio, and 10 minutes extraction time, the extraction results are summarized as follows:
Sulfur inSulfurOilSolventRecovered Oil (%)Reduction (%)Recovery (%)Acetonitrile0.3855.479.5DMF0.2768.572.0
The data suggest that the solubility of oil in the solvents (each of which contained 5% water) was very high and as a result the oil recovery (in the oil phase) was only 70 to 80% in the one-stage extraction. Based on these results, it is expected that using the same solvents in dry form in a multi-stage extraction for 90% sulfur reduction (that is, from 500 to 50 ppm) would result in an even lower oil recovery since dry solvents have correspondingly even higher solubilities for oil as compared to the same solvents containing water. This means a bulk quantity of oil (equivalent to more than 30% of the oxidized oil) has to be recycled with the sulfur oxides to the HDS unit in order to reduce the oil loss in the process described in the patent.